SOX AND NOx REMOVAL FOR COAL-FIRED BOILERS IN JAPAN

by

Jumpei Ando

Faculty of Science and Engineering

Chuo University

Tokyo, Japan

to be presented at

THE SEVENTH SYMPOSIUM ON FLUE GAS DESULFURIZATION

Hollywood, Florida

May 17-20, 1982

Although fhe research described In this paper has belllf

funded wholly or in part by the Un;ted States Environmental

Protection Agency. it has not been ~"'I~-'~rl to Agency

review and therefore does not neC3 -:z-. "12 vieWS

01 the Agency and no offici::1 endorsem' '~rred..

IPHAB004228
sax AND NOx REMOVAL FOR COAL-FIRED BOILERS IN JAPAN

Jumpei Ando

Faculty of Science and Engineering

Chuo University, Tokyo

ABSTRACT

Combined sax and ~Ox removal from flue gas from coal combustion has

become more and more im~ortant with the increase of coal-fired boilers.

Stringent Legulations in Japan necessitate the combined removal even for

flue gas containing about ZOO ppm each of SOx and NOx derived from

controlled combustion of low-sulfur coal. Flue gas cleaning, including

selective catalytic reduction (SCR) of NOx ' electrostatic precipitation,

and the wet limestone-gypsum flue gas desulfurization (FGD) process, has

been applied successfully to three coal-fired boilers, removing 50-85iof NOx ' 99.9-99.95% of particulates, and 90-957. of SOZ' Thirteen similar

cleaning plants are under construction for coal-fired boilers.

Ammonia at the SeR reactor outlet is maintained below 5 ppm so as to

give no adverse effect on FGD and the quality of fly ash, although

wastewater treatment to remove ammonia may be required in certain regions.

Cost of SCR is about one-third that of FGD by the limestone-gypsum

process in both investment and operation. The power generation cost,

including the flue gas cleaning and wastewater treatment, is less than

that with low-sulfur oil without flue gas cleaning. The development of

the combined cleaning system for coal has contributed significantly to

save oil and to solve the energy problem in Japan. Simultaneous SOx and

NOx removal by the electron beam and activated carbon processes has been

tes ted.

IPHAB004229
1. INTRODUCTION

Ambient SOZ concentrations in Japan have been lowered remarkably to meet

the stringent air quality standard of 0.04 ppm daily average (equivalent

to 0.02 ppm yearly average) in nearly all regions due to the strenuous

efforts of SOx abatement including the construction of more than 1400

commercial FGD units.

For NOx abatement. combustion modification has been applied to more than

100,000 gas sources which provide about 95% of total flue gas. NOx concentrations in flue gases from utility boilers have been reduced by

combustion modification to 200-300 ppm for coal, 80-120 ppm for oil, and

40-80 ppm for gas. Automobile emissions have been controlled by the

most stringent regulations, including 0.Z5 g NOx/km for gasoline-engined

passenger cars. The fact that ambient N02 concentrations exceed the

strict standard (Table 1) in several regions indicates that flue gas

treatment (FGT) for NOx removal is needed.

TABLE 1. AMBIENT AIR QUALITY STANDARDS, ppm

S02 NOZ

Daily Yearly Daily Yearly

Country average average average average

Japan 0.04 0.02 0.04- 0.02-

0.06 0.03

U.S.A. f).03 0.05

West Germany 0.05 0.05

A recent Environment Agency (Japan) report(1) claims that, to use coal,

the combustion gas should be cleaned to a level equal to that of the gas

from low-sulfur oil.

Many simultaneous SOx and NOx removal processes have been studied for

several years. Some of the processes have been applied commercially to

relatively small oil-fired industrial boilers (10-40 MW equivalent);

they have not yet been applied to larger gas sources because of problems

with the processes. On the other hand, selective catalytic reduction

(SCR) of NOx ' using ammonia and a catalyst at 300-400°C to convert NOx to NZ and H20, has been developed and applied to more than 130 gas sources,

including coal-fired utility boilers. Table 2 shows major coal-fired

utility boilers in operation and the SOx and NOx concentrations in their

flue gases.

This paper mainly describes FGD and combined SCR/FGD for coal-fired

boilers; it briefly describes simultaneous SOx and NOx removal processes.

Z

IPHAB004230
TABLE 2. EXAMPLES OF NOx AND SOx EMISSIONS FROM COAL-FIRED UTILITY BOILERS

NOx , ppm SOx, ppm

Power New (N) or Capacity, Boiler SCR FGD FGD Reheater

company Station retrofit ( R) MW out out in out out

EPDCa Isogob R 265 200c 450 20 30

EPDC Takasago R 250 350 1500 100 140

EPDC Takasago R 250 350 1500 100 140

EPDC Takehara R 250 400 80 1700 100 140

EPDC Matsushimab N 500 300d 1000 60 100

Chugoku Shimonoseki R 175 400 190e 750 45 80

Electric

Hokkaido Tomato-Atsumaf N 350 200g 30 230 10 20

Electric

aElectric Power Development Company.

bSubjecting 75% of the gas to FGD.

CWith DF-CN burner, two-stage combustion (TSC), and domestic low nitrogen coal

(1% or less).

dUsing imported coal with SGR burner, TSC, and flue gas recirculation (FGR).

eCan be lowered to 80 ppm when needed.

fSubjecting 25% of the gas to SCR and 507. of the gas to FGD.

gUsing domestic coal with dual-register burner, TSC, and FGR.

2. FGD UNITS FOR COAL-FIRED BOILERS

2.1 Types of Lime/Limestone FGD Processes

All FGD units for coal-fired boilers in Japan use lime/limestone

scrubbing, which may be classified in four types as shown in Figure 1

and Table 3. Type I is the throwaway sludge process, typical in the

U.S.A. There is only one Type I unit: it is at Omuta and was

constructed by Mitsui Miike Machinery Co. Other units use limestone and

oxidize calcium sulfite to gypsum. To completely oxidize calcium sulfite

to gypsum, it is usually necessary to lower the pH of the sulfite slurry

to about 4. With a catalyst, complete oxidation is attained at a pH of

about 5. Type II units lower the pH to about 5 using three scrubbers

and a catalyst for oxidation. There are three Type II units: one owned

by Mitsui Aluminum (Omuta unit No.2) and two by EPDC at Takasago.

3

IPHAB004231
Type

(I)

-~ CG

- --,

i

v Pond t ' I//' 7/~'/ 17/(7~/<////d

(II)

----r FG I

I

I

I

,

s

r-- -,

,............'-,. -- - --~

,

... ~------

Gypsum

-~ CG

(III) CaC03 LtJ--l

I ~.1 I p,'

f-----------~~:5fJ)-- -- 4'

Air - - -- _1 Gypsum

CaC03

Air - ----'

H?O

- ,- - - -,. CG

',-------L~ ---I

t

---[fJ- - -.L - .-,ww

Gypsum

(IV)

FG: Flue Gas CG: Cleaned gas s: Scrubber

ps: Prescrubber OX: Oxidizer C: Centrifuge w~: Wastewater

- - - Gas ----~Liquor -----~)Slurry or Solids

Figure 1 Types of Commercial Wet Lime/limestone FGD Process for Coalfired Boilers in Japan

4

IPHAB004232
TABLE 3. FGD AND SCR UNITS FOR COAL-FIllED BOILERS

Boller FGD SCR

owner Plant 51 te No. HW N!Ra Constructor Complet 10n Type Constructor Co.ple.tion

Hi tsu 1

AlumJnum Omura 156 R MHHC b 1972

175 N IlMHC 1975 II

EPDC Takasago 250 R MHHC 1975 II

250 R MHHC 1976 II

1sogo 265 R I tile 1976 III

265 R IHI 1976 III

Takehara 250 R BHKd 1977 III BHK. KHI 1980

700 N IHI 1983 IV BHK 1983

Matsush1ma 500e N IHI 1981 IV

2 500e N BHK 1981 IV

Chugoku

MIll Electric f ShillOno.eki 175 R 1979 IV !illI 1980

5hln-Ube 75 R MIll 1982 IV /illI 1982

75 R /ill I 1982 IV !'!HI 1982

156 R MIll 1982 IV /illI 1982

Hi zus hima 125 R BHK 1983 IV IlHK 1983

2 156 R BIlK 1983 IV BKK 1983

P.akkalca

Electric: Tom.ato-AtsI.JDla 350g N BHK 1980 IV BHK 1980

600 N MIll 1984 IV

kYUS nu

nee tei e Omura 156 R :1111 1982 IV !'lIII 1982

Minato 156 R If'iMC 1983 III' :1111 1983

laban

.Joi~t ~ak.oso 8 600 N MIll 1983 IV HIlI 1983

bOG N /illI 1983 IV IHI 1983

TonoKu

El'.!ctrl c Sendai 175 R BHK 1983 IV BHK 1983

j 75 R BHK 1983 IV BHK

Tokyo

nectei c YOk.OBuk.a 265 R /ill I 1984 IV IlHI 1984

265 R l1HI 1984 IV HlI1 1984

5hi koku

Electei c Saijo 175 R KHl h 1983 IV'

250 R KHI 1984 IV'

aNe"" or retrafi t.

b!1itsui 'Ulke !1achinery Company.

CIsh1kawajJma-Har1ma Heavy Industries.

dBabeock-Hitachi K.K.

eSubjecting 75:: of the gas to FGD.

flU tsublshi Heavv Indus tri es

gSubjectlng 50% of the gas to FGD and 25% of the gas to SCR.

hKawasakl Heavy Industrl es.

IPHAB004233
Type III units have two-stage scrubbers and lower the pH of slurry at

about 5 to about 4 by adding a small amount of sulfuric acid. Type III

units require less investment cost than Type II units and may be preferred

where sulfuric acid is available at a reasonable cost. There are three

Type III units, all owned by EPDC: two at Isogo were constructed by

Ishikawajima-Harima Heavy Industries (IHI) and one at Takehara was

constructed by Babcock-Hitachi (BHK).

Type IV units have a prescrubber with a separate liquor loop and use

sulfuric acid for pH control. The prescrubber: (1) removes fly ash in

the gas to reduce erosion of the scrubber system and to increase the

purity of the gypsum; (2) removes chloride and fluoride from the gas to

protect the scrubber system from corrosion (the fluoride removal may

also increase both 502 removal efficiency and limestone utilization,

possibly because fluoride reacts with limestone to form a coat of

insoluble calcium fluoride on the surface of the calcium carbonate

particles); and (3) cools the gas to eliminate scaling in the scrubber.

Type IV units, developed by !1itsubishi Heavy Industries (!'!HI) since the

19605, have been applied to more than 30 FGD units by MHI, mainly for

oil-fired boilers; it was applied to a coal-fired boiler of Chugoku

Electric at 5himonoseki in 1979. All of toe limestone scrubbing units

constructed since 1979 are Type IV, including those to be constructed ov

IHI and BHK (Table 3). The Type IV unit prescrubber treats a hot flue

gas with an acidic liquor with a pH of about 1, containing considerable

amounts of chloride, fluoride, and fly ash. Therefore, the prescrubber

requires highly corrosion- and erosion-resistant materials; for example,

silicon carbide is often used for the spray nozzles. However, the

prescrubber substantially reduces troubles in the scrubber system. All

units with a prescrubber--the units at Shimonoseki, Tomato-Atsuma, and

Matsushima--have been operated with 100% reliability since their startup (Table 4). The two scrubber systems for two 500 MW boilers at

Matsushima are operated by only two persons per shift (one person each).

TABLE 4. OPERATI~G HOURS OF BOILER AND FGD (OCTOBER 1980 - SEPTEMBER 1981)

New (N) Hours FGD performance, %

or Boi ler FGD FGD called Oper- Reliretr 0- Operation Operation to operate ability abili ty

fi t (R) (A) ( B) (C) (B/A) (Bi C)

Shimonoseki R 7918 a 7825 7825 98.8 100.0

Tomato-Atsuma 827S b 8263 8263 99.9 100.0

Matsushima N 3968c 3968 3968 100.0 100.0

(Boiler No. 1)

aBoiler underwent annual ;naintenance in March and April 1981.

bBoiler started operation in October 1980.

cJanuary to June 1981. Boiler started operation i~ January 1981.

6

IPHAB004234
The two units to be constructed by Kawasaki Heavy Industries (KHI) for

Shikoku Electric (Table 3) will use the magnesium gypsum process(3) with

a prescrubber with a separate liquor loop (Type IV'). Chiyoda may construct

two FGD units for coal-fired utility boilers by the jet bubbling limestonegypsum process(3) using also a prescrubber with a separate liquor loop.

The only unit under construction by the limestone-gypsum process without

a prescrubber is that by MMMC for the Minato Station of Kyushu Electric

(Table 3). A single spray tower will be used for 90% 502 removal using

a catalyst and also sulfuric acid for pH control (Type III').

Most of the U.S. systems have no prescrubber but have a stand-by scrubber

which is not installed in Japan. Moreover, the S02 removal efficiency

by limestone scrubbing seems lower than that with the. Type IV system in

Japan by which about 95% removal is attained without any additive such

as adipic acid used in the U.S.A.

The prescrubber may not be preferred for throwaway sludge systems that

can be operated without scaling in the unsaturated mode. For the gypsum

by-producing process, the prescrubber may be preferred, because the

overall cost of power generation (including FGD) may be lowered by the

high reliability of the FGD system.

2.2 Scrubber Types and Operating Parameters

Table 5 shows the capacities, types of scrubbers, and operating parameters

of FGD units for utility boilers. The two EPDC units at Matsushima

currently treat nearly 80% of the flue gas from the 500 MW boilers,

while Hokkaido Electric's unit at Tomato-Atsuma treats 50% of the flue

gas from a 350 MW boiler. Other units treat 100% of the flue gas from

the boilers they serve.

EPDC's five FGD units at Isogo No.1 and No.2, Takasago No.1 and

No.2, and Takehara were constructed between 1975 and 1977 and use

venturi scrubbers or combined venturi and perforated plate scrubbers

which give a high dust removal efficiency but a large pressure drop

(325-615 mm H20 across two scrubbers), resulting in a high power

consumption (2.2-2.6% of the power generated by the boiler). The

relatively low consumption at Isogo (2.2%) is due to the low inlet S02

concentration of 450 ppm.

Chugoku Electric's FGD unit at Shimonoseki, constructed in 1979 by MEl

using a combined spray tower (semi-venturi) prescrubber and plastic-grid

packed tower, gives a lower pressure drop and consumes less power (Z.1%).

7

IPHAB004235
IJ

TABLE 5. OPERATl NG PARAMETERS OF FGO UNITS FOR COAL-FIRED UTILITY BOILERS (LIMESTONE-GYPSUM PROCESS)

Owner EPOe EPDC EPDC EPDC Chugoku Hokkaido

Station Isogo Takasago Takehara Matsushima Shimonoseki Tomato-Atsuma

Boiler No. 1 1 1 1 2 1 1

Capacity, MW 256 250 250 500x3/4 500x3/4 175 350xl/2

Gas treated, 1,000 Nm 3/hr 821 792 793 1,300 1,300 610 610

FGD constructor Hila MMb BIIKc IHI BilK MHId BILK

FGD start-up 1976 1975 1977 1981 1981 1979 1980

Inlet S02' ppm 450 1,500 1,730 1,000 1,000 730 230

Inlet dust, mg/Nm3 1,500 100 lOO 300 300 830 25

1st scrubber (prescrubber) Ventu ri Venturi Venturi Spray Spray Spray Venturi

L/G, ltter/Nm3 7 6 2.5 3 3 3 2.2

2nd scrubber (scrubber) Ventu ri Venturi ppe Spray Spray Packed ppe

L/G, l1ter/Nm3 7 6 7 15 15 14 5

Outlet S02, ppm 20 100 100 60 60 45 10

Outlet dust, mg/Nm) 50 30 50 30 30 50 5

SOx removal efficiency, % 95.5 f 93.3 f 94.2 f 94.0g 94.0g 93.8g 95.7g

Dust removal efficiency, % 96.6 70.0 87.5 90.0 90.0 94.0 80.0

Pressure drop, mm "20 36011 325 h 615 h 145 i 133 i 240h 450j

Wastewater, t/hr 10 7.5 12 15 15 2.2

Power requirement, %k 2.2 2.6 2.6 2.2 2.1 1.7

Gas reheating facility OFI or! orI Gr.II'" GC;IIIR GGlim GGnm

- --'--. - '--- - - ---- --

"'U

I

»

OJ

o

o

I\J

W

0'>

alshikawaJlma-liarim8 Heavy Industries.

bMltsui Milke Machinery Company.

cBabcock-ll1tachi K.K.

dMitsubishi Heavy Industrl es.

eperforated plate.

f l- 3% lower after reheating by oil-firing.

gAbout 90% after gas reheating by gas-gas heater.

hBy scrubbers and mist eliminators.

i By scrubbers.

jBy scrubbers, mist eliminators, and gas-gas heater.

kpercent of power generated.

lOil firing.

mGas-gas heater.
Hokkaido Electric's Tomato-Atsuma unit, constructed by Babcock Hitachi

(BHK) in 1980, uses an improved scrubber with lower pressure drop and

smaller power consumption than the Takehara unit constructed by BRK in

1977 (power consumption is 1.7% vs. 2.6%). The low power consumption is

due to the improved design and the low inlet 502 concentration of around

230 ppm.

The two EPDC units at Matsushima, completed in 1981 by IHI and BRK for

500 MW boilers, use spray towers with a low pressure drop of 133-

145 mm H20. The new EPDC uni t for, the Takehara No. 3 boiler, being

constructed by IHI, also uses a spray tower. The power consumption of

Matsushima No.2 is 2.2%.

MHI used a spray tower absorber for the first lime-gypsum process unit

(20 MW equivalent) constructed in 1964 but has used a plastic-grid

packed tower since 1972 as the scaling problem was solved, because the

packed tower can be more efficient than the spray tower. The spray

tower may have a high efficiency for a large scrubber with a height of

over 30 m, such as constructed recently at Matsushima and Takehara

(No.3). The operation of those large units and three 600 MW units to

be constructed by MHI for Joban Joint Power and Hokkaido Electric

(Table 3) with plastic-grid packed tower will show a good comparison of

the scrubbers.

All of those units use finely ground limestone so that over 95% passes a

325 mesh screen at a stoichiometry of 1.00-1.05 to remove 94-97% of

502. Gas reheating adds a small amount of 502 so that the overall S02

removal efficiency is 90-95%. The reheating has been by oil-firing at

Isogo, Takas ago , and Takehara (No.1) and by gas-gas heater (Ljungstrom

heat exchanger) at the new units.

The dust removal efficiency of the scrubber systems ranges from 70 to

96%. EPDC's FGD units at Isogo are designed for over 95% dust removal

efficiency because the boilers use low-sulfur coal for which the

conventional cold-side electrostatic precipitator (ESP) is not highly

efficient. On the other hand, the EPDC boilers at Xatsushima and that

of Hokkaido Electric at Tomato-Atsuma use hot-side ESPs which are

efficient for low-sulfur coal; therefore, the 80-90% dust removal

efficiency of the FGD unit is sufficient.

3. SELECTIVE CATALYTIC REDUCTION AND ITS COMBINATION WITH FGD

3.1 Selective Catalytic Reduction (SCR)

Ammonia selectively reacts with NOx in gases at ISO-450°C in the

presence of a catalyst and oxygen. SCR can be conveniently applied to

boiler economizer outlet gas at 300-400°C.

9

IPHAB004237
4NO + 4NH3 + 0z = 4NZ + 6HZO

Early in its development, SCR had serious problems. The major ones

were: (1) catalyst poisoning by SOx in the gas; (Z) plugging of the

catalyst by dust; (3) deposit of ammonium bisulfate on the catalyst at a

low temperature (around 300°c or below) due to reduced boiler load;

(4) ammonium bisulfate deposit in an air preheater downstream of the SCR

r.eactor; (5) promotion of oxidation of S02 to 503 by the catalyst; and

(6) erosion of the catalyst by fly ash from the coal.

Solutions of those problems include: Problem (l)--using base metal

catlysts based on Ti02 instead of AIZO) or FeZ03; Problem (2)--using

parallel-flow catalysts or reactors such as honeycomb, plate, and tube

catalysts or parallel passage reactors (soot-blow may be applied if

needed); Problem ()--maintaining the gas temperature above about 300°C

by using economizer by-pass when needed; Problem (4)--keeping NH3 leakage

(ammonia in the SCR reactor outlet) at a low (e.g., below 5 ppm) level;

Problem (5)--developing low-oxidation catalysts (depressing oxidation

also helps solve- Problems (3) and (4»; and Problem (6)--using moderate

gas velocity, hard catalyst, and a device (e.g., a dummy spacer) for

erosion prevention.

SCR is simple, and an SCR unit is usually operated automatically (without

an operator).

Figure 2 shows the relationship of inlet NH)/NOx mole ratio to NOx removal efficiency and NH3 leakage. Usually NH3 leakage is kept below

5 ppm to eliminate an ammonium bisulfate problem. For 80% NOx removal

for flue fas from coal, a ratio of 0.85 and space velocity of nearly

3,000 hr- may be used; for 90% removal, a ratio of 0.95 and space

velocity of about 2,000 hr- 1 may be used. Flue gas from oil combustion

can be treated with 30-50% less catalyst because a much more active

catalyst (porous and soft) can be used.

Figure 3 shows the effect of boiler load on SCR performance. At a

reduced load-, gas temperature is lowered but NOx removal efficiency is

raised because of the longer reaction time due to the reduced gas flow

rate. A gas temperature above about 330°C is desirable because ammonium

bisulfate tends to deposit on the catalyst at lower temperatures.

3.2 Combination of SCR and FGD

Figure 4 shows combined SCR-FGD systems for coal-fired boilers. The SeR

reactor of the Shimonoseki unit (A) treats flue gas with a full dust

load of about ZO g/Nm3 (high-dust system). Those of the Tomato-Atsuma

and Takehara units (B and C) treat the gases leaving a hot ESP containing

less than 0.1 g/Nm3 of dust (low-dust system). Both systems have been

operated with neither erosion nor plugging of the catalyst by fly ash.

10

IPHAB004238
NOx Removal

[ - J0 NH3 leakage _ 5~g;_

80

90

Figure 3 Boiler Load and Performance of SCR

100

::[~J

[ 502 Oxidation to 503 J1 B

:::r~~O 200[ I ! I ,J

25 50 75 100

Boiler load (%)

100

.......

N

'-"

..... 90 Ql

:>

0

s

Q) 80 CG

X

0

z 70

·60

NH3/NOx mole ratio

.......

S

0.

0. 20 Q)

00

Ql

ry\)\J Ql 10 Q)

..... u l-' 0

C") 0 S~·· '-"

:::c

z 0.6 0.7 0.8 0.9 1.0 1.1

Figure 2 SCR for Coal-fired Boiler

Flue Gas

(350°C; Honeycomb Catalyst)

11

IPHAB004239
A: Shimonoseki Plant, Chngoku

Electt!:c

Boiler

Bypass

AP

Ammonia

tank

FGD

Stack

Baile Hot

Eco ESP

Boiler

Eco

Eco: Economizer APR: Air Preheater

B: Tomato-Atsuma Plant, Hokkaido

Electric

Stack

C: Takehara Plant, EPDC

Wastewater

treatment

(NH3 removal)

MC: Multi-cyclone

ESP: Electrostatic Precipitator GGH: Gas-gas Heat Exchanger

Figure 4 Combined SCR-FGD System in Operation for Coal-fired Boilers

12

IPHAB004240
The properties of fly ash, however, may be considerably different with

the type of coal and the condition of combustion. The effects of

various fly ashes on SCR should be further studied.

Hot ESPs are more costly than cold ESPs, but are more efficient for

collection of dust from low-sulfur coal. Most of the SCR units under

construction use the high-dust system because the deposit of ammonium

bisulfate in the air preheater is eliminated by the cleaning effect of

the fly ash, and because the dust can be sufficiently removed by the

combination of the cold E5P and wet FGD.

SCR units usually give less than 5 ppm NH3 leakage which is caught by

wet FGD units. With Type I, II, or III FGD units, ammonia enters the

scrubber system. The ammonia may not affect scrubber operation but may

increase S02 removal efftciency.(2) With the Type IV unit, ammonia is

caught by the prescrubber. In any case, ammonia at the scrubber outlet

is virtually nonexistent; there is not the plume problem that is usually

experienced at ammonia scrubbing FGD units.

With the high-dust system, a small amount of ammonia, 0.01-0.02% for 3-

7 ppm ammonia leakage, may be contained in the fly ash caught by the

cold ESP. The fly ash at Shimonoseki, where ammonia leakage is kept

below 1 ppm, contains very little ammonia, and therefore gives no

trouble when used as an additive to cement or for landfill.

3.3 Wastewater and Its Treatment

The pH and composition of wastewater from commercial FGD units for coalfired boilers in Japan are shown in Table 6. The wastewater (from the

prescrubber and scrubber) is treated with lime to precipitate heavy

metals and fluoride which are filtered off. The filtrate is usually

treated by ion exchange resin to remove dithionate 52°62- which causes

chemical oxygen demand (COD).

Usually the treated water contains below 10-15 mg/liter each of

suspended solids and COD, below 15 ppm fluoride, and below 1 ppm oily

material at pH 6.5-8.5. It thus satisfies existing regulations.

As shown in Table 6, the wastewater contains a considerable amount of

nitrogen compounds which may be derived mainly from NOx in the flue gas.

Flue gas from a coal-fired boiler usually contains 200-500 ppm NOx ' If

1-27. of the NOx is absorbed by the scrubbing liquor, the nitrogen content

of the wastewater reaches 100-600 ppm as shown in Table 6, assuming that

a 250 MW FGD unit purges 10 t/hr wastewater. So far, wastewater has not

been treated to remove nitrogen compounds, because the total amount of

nitrogen compounds is not much.

13

IPHAB004241
TABLE 6. pH AND COMPOSITION (mg/liter) OF WASTEWATER FRmt FGD UNITS

FOR COAL-FIRED BOILERS ("BEFORE BEING TREATED) (l)

pH 5

Chemical oxygen demand 30 100

Suspended solids 2.,000 J,OOO

Fluoride 500 600

Iron 100 500

Manganese 10 30

Magnesium 200 1,000

Aluminum 100 1,400

Chloride 3,000 8,000

Total Nitrogena 100 600

aDoes not include ammonia derived from SCR of NOx '

When SCR is applied upstream of FGD, ammonia is caught by the scrubber.

Ammonia at a concentration of 5 ppm in flue gas from a 250 coal-fired

boiler amounts to about 3 kg/hr. If the FGD unit for the boiler purges

10 t/hr of wastewater, the scrubber (or prescrubber) liquor as well as

the wastewater may contain about 300 mg/liter of ammonia.

Adding lime causes much of the ammonia to be volatilized. If necessary,

even more ammonia can be removed from the water. EPDC's demonstration

plant at Takehara (combined SCR and Type II FGD) has a unit to remove

ammonia from wastewater by a conventional activated sludge process;

ammonia is reduced to 10 mg/liter. The Takehara plant faces the Seto

Inland Sea which occasionally has a "red tide" problem. Therefore,

reducing ammonia to a low level is desirable.

In Japan, a small amount of ammonia has been added to the flue gas from

oil-fired utility boilers to neutralize sulfuric acid mists and to protect

ESPs from corrosion. Thus ESP outlet gas usually contains about 5 ppm NH3

which is caught by wet-process FGD and contained in the wastewater. At

Chubu Electri's Owase-Mita plant. an ammonia stripping unit has been

operated to reduce ammonia in FGD wastewater.(3)

When SCR is combined with a Type I FGD system, ammonia may be caught in

the calcium sulfite slurry and may accumulate in the sludge pond when

the supernatant is recycled to the scrubber. It may be necessary to

minimize the ammonia emission from the SCR reactor.

14

IPHAB004242
It is likely that the nitrogen compounds shown in Table 6 will be

reduced considerably by applying SCR and reducing NOx in flue gas. It

may be possible that the total nitrogen compounds (including ammonia)

may be lowered by applying SCR and keeping ammonia leakage at a very low

level; e.g., 1 ppm or below at the Shimonoseki plant.

4. ECONOMICS OF FGD AND SCR

Investment costs of limestone-gypsum process FGD units for coal-fired

boilers are listed in Table 7. The cost of the first units completed

in 1975-1976, was 18,600 yen/kW.* The investment cost has since

continued to increase mainly because of inflation. Chugoku Electric's

Shimonoseki plant is fairly costly because it includes a Ljungstrom gasgas heater to reheat the gas to 110-120°C. The gas-gas heater accounts

for about 10% of the investment cost but, since it does not require fuel

oil for gas heating, gives an overall economic advantage.

TABLE 7. INVESTMENT COST OF FGD UNITS FOR COAL-FIRED BOILERS

(LIMESTONE-GYPSUM PROCESS, RETROFIT)

Plant Capacity, Investment cost Year

Power company si te MW 109 yen yen/kWhr completed

EPDC Takasago 250 x 2 9.3 18,600 1975-1976

EPDC Isogo 265 x 2 11.0 20,750 1976

EPDC Takehara 250 7.2 28,800 1977

Chugoku Electric Shimonoseki 175 7.0a 40,OOOa 1979

aIncludes Ljungstrom gas-gas heat exchanger.

The estimated annualized FGD cost using a gas-gas heater for a 500 MW

coal-fired boiler is about 1.9 yen/kWhr including 7 years depreciation.

The fixed cost is 70% of the annualized cost.

Investment costs of SCR units for coal-fired boilers are shown in

Table 8. As shown in Table 9, an SCR unit for a large new, coal-fired

boiler costs 6,700--8,400 yen/kW for 80% NOx removal and about 30% more

for 90% removal. An SCR unit for an existing boiler may cost 10-40%

more. The annualized SCR cost is 0.6-0.8 yen/kWhr for 80% removal and

nearly 30% more for 90% removal. Actually it is difficult to remove 90%

of NOx with NH3 leakage below 5 ppm for a large boiler because both gas

flow rate and NOx concentration are not uniform in a large duct. Catalyst

cost is over 60% of both investment and annualized costs.

*1J!1 - $0.0043

15

IPHAB004243
TABLE 8. INVESTMENT COST OF SCR UNITS FOR COAL

Size New (N) or Cost

Station (MW) Retrofit (R) Constructor Start-up (yen/kW)

Shimonoseki 175 R MIll 1980 9,700a

Tomato-Atsuma 350x1/4 N BRK 1980 10,eOOb

Takehara 250x1l2 R BRK 1981 7,OOOb

Takehara 250x1/2 R KHI 1981 S,OOOb

aIncluding boiler modification for econom~zer by-pass.

bApproximation.

TABLE 9. E:STIMATEl> SCR COST FOR NEW 700 HW UTILITY BOILERS

(Flue gas 2,300,000 Nm3/hr. Annual power generation

4,292,400 MWhr. 70% utilization. NR3 leakage less

than 5 ppm. Honeycomb catalyst,)

Fuel Hi2h S coal Hi2h S coal Low S coal

Inlet SOx (ppm) 2500 2500 600

Inlet NOx (ppm) 600 300 300

NOx removal (%) 80 90 80 90 80 90

Space velocity (103 hr-1) 2.2 1.6 2.7 -Z.O 3.0 2.2

Invest~ent costa

103 yen/kW 8.44 10.76 7.26 9.10 6.69 8.51

U.S. S/kWb 36.7 46.8 31.6 39.6 29.1 37.0

Annualized costC

yen/kWhr 0.81 1.04 0.65 0.82 0.59 0.76

mill/kWhr 3.5 4.5 2.8 3.6 2.6 3.3

S/lb of NOx removedd 0.48 0.56 0.79 0.88 0.71 0.82

alncluding initial charge of catalyst, civil engineering, and test operation.

Catalyst: 3.5 x 106 yen/m3 , 2 years life.

bSl - Y 230.

clncluding 10% interest and 7 years depreciation.

dNOx calculated as NOZ (1 lb = 0.45 kg).

16

IPHAB004244
A rough estimated cost for power generation is shown in Table 10. About

20% of the total investment for a coal-fired power station is for flue

gas cleaning by FGD, SCR, and ESP. The investment cost of FGD is about

70% of the cost for flue gas cleaning. The estimated annualized cost of

power generation with coal is 17 yen/kWhr, including nearly 3 yen for

the flue gas cleaning. The cost is less than that with low-sulfur oil

without flue gas cleaning.

TABLE 10. ESTIMATED POWER GENERATION COST (1981)

Investment cost, yen/kW

Coal-fired power station (excluding flue gas cleaning)

Flue gas desulfurization (90% efficiency)

Selective catalytic reduction (80% efficiency)

Electrostatic precipitator (99.5% efficiency)

Total

Annualized cost, yen/kWhr

Flue gas desulfurization

Selective catalytic reduction

Electrostatic precipitator

Total power cost with coal including flue gas cleaning

Power cost with low-sulfur oil without flue gas cleaning

s. SIMULTANEOUS SOx and NOx REMOVAL

5.1 Outline

200,000

32,000

7,000

4,000

243,000

1.9

0.6

0.1

17.0

20.0

Major simultaneous SOx and NOx removal processes are shown in Table 11.

The copper oxide process has been applied to an oil-fired industrial

boiler (40 MW equivalent).(4) Wet processes using Cl02 or 03 as the

oxidizing agent and NaOH or CaC03 as the absorbent have been used for

several gas sources (10-20 HW equivalent).(4) There is no plan for

further application of those processes. The application of activated

carbon and electron beam processes to coal-fired boilers has been studied.

Wet processes using alkaline solutions containing EDTA and FeS04 to

absorb 502 and NO have been tested but are not commercialized yet.

Pilot plant tests of fluidized-bed combustion (FaC) of coal (S HW

equivalent) are in progress at EPDC's Wakamatsu Station. Preliminary

tests with domestic low-sulfur low-nitrogen coal indicated that NOx was

lowered to about 60 ppm.(S) FBC, however, may not be used widely in

Japan because of the difficulty in disposing of ash containing calcium

compounds. Although tests are planned to use a synthetic absorbent

which may be separated from fly ash for reuse, the method may not be

practical. '

17

IPHAB004245
TABLE 11. MAJOR SIMULTANEOUS SOx AND NOx REMOVAL PROCESSES

Type

Dry process

Absorbent, reagent By-product

Copper oxide. NH3 N2 and S

Activated carbon, NH3 N2 and S

Electron beam, NH3 (N14)2S04 and NH4 N03

Wet process CI02, NaOH

D3' CaCD]

K2S04. EDTA. FeS04

Na2SD2. NaCI. and NaN03

CaS04.2H2D. and N2 or NH3

N2 and S

5.2 Activated Carbon Process(6)

Electric Power Development Co. (EPDC) and Sumitomo Heavy Industries

(SHI) have conducted joint tests of the activated carbon process with a

target of removing 95% of SOx and 40% of NOx in flue gas from a coalfired boiler. A pilot plant with a capacity of treating 10,000 Nm3/hr

of flue gas from a coal-fired boiler at the EPDC's Takehara Station was

operated from 1978 through 1980. The gas leaving an ESP at 120-150°C

was added with 0.7 mol NH3 to 1 mol SOx and was passed through a moving

bed of activated carbon. Over 90% of SOx was adsorbed by the carbon

with a space velocity of 500-900 hr-1, while 20-40% of NOx was removed

(Figure 5). The carbon was heated in a separate moving bed at 35DoC by

a hot inert gas to release concentrated S02' The carbon consumption was

0.5-1% per day.

The concentrated 502 was mixed with a small amount of air and introduced

into a shaft furnace charged with anthracite coal or coke. By partial

combustion in the furnace. gas temperature reached 900°C. About 90% of

the 502 was reacted: about 45% to form elemental sulfur, 30% to form

H2S, and 10% to form COS. The gas, cooled to separate elemental sulfur

by condensation. was led to three Claus furnaces in series to which a

portion of the concentrated 502 was also added to react with H2S to form

elemental sulfur. Thus 90% of the 502 recovered by the carbon was

converted to elemental sulfur. The tail gas from the Claus furnace was

incinerated and returned to the FGD system.

Ammonia played two roles: it reduced NOx ; and it reduced carbon

consumption. The process may suit a flue gas with relatively low SOx

content because the consumption of both ammonia and carbon decreases

with SOx content. SRI claims that the process may compete with the wet

limestone process for coal containing 1% or less sulfur. A demonstration

plant with a capacity of treating 300.DOO Nm3/hr of flue gas from a

coal-fired bOiler will be constructed at EPDC's Matsushima Station i~

1984.

18

IPHAB004246
5.3 Electron Beam Process

Ebara Corporation and Japan Atomic Energy Research Institute have

jointly developed a unique process to remove SOx and NOx simultaneously

by electron beam radiation in the presence of ammonia. By the radiation,

SOx and NOx form fine crystals of ammonium sulfate and nitrate, which

are caught by an ESP or baghouse (fabric filter). The by-product is

useful for fertilizer. A pilot plant with a capacity of treating 3,000-

10,000 Nm3/hr of flue gas from an iron-ore sintering machine was operated

in 1978 (Figure 6).(7)

The process has been licensed to AVeO, U.S.A., which has tested the

effects of coal fly ash on the process; the ash had no adverse effect on

the process.(8) Over 70% removal of fly ash may be needed prior to the

radiation to make the product useful for fertilizer. AVCO estimates

that the investment cost is less than that for conventional wet lime

scrubbing when a large size electron beam gun is used. Such a gun may

be commercialized in the near future. Ebara estimates that the power

consumption for treating flue gas from a coal-fired utility boiler is

about 3% of the power generated by the boiler. The figure is a little

larger than the consumption by the combination of SCR (0.1-0.2i.) and FGD

(2.0-2.5%). Although there are many simultaneous SOx/NOx removal processes,

the electron beam process may be the only process which may be useful in

large-scale to recover SOx' NOX, and NH3 as useful by-products.

6. SUMMARY

Most coal-fired boilers in Japan are to use a flue gas cleaning system

consisting of selective catalytic reduction (SCR) using a honeycomb or

plate catalyst, electrostatic precipitators, and FGD by the limestonegypsum process using a prescrubber with a separate liquor loop. The

power generating cost by coal, including gas cleaning and wastewater

treatment, is less than that by low-sulfur oil without gas cleaning.

The fuel for several oil-fired boilers is to be changed to coal, using

gas cleaning. However, the limestone-gypsum process is fairly costly.

SCR is much less costly than FGD but is more costly than combustion

modification (CM), and should be used with CM when CM alone is not

sufficient to meet existing regulations. Simultaneous SOx/NOx removal

processes and fluidized-bed combustion have not yet been proved to be

better alternatives to combined cleaning. Further development of SOx

and NOx removal processes is desired.

19

IPHAB004247
100

"'"'

....

N

..... ~2 til

:>

0

E

...

OJ

90

~: 5 80 r.rJ

;; 40

~: .....

:>

...

iii

g 30

~3

20 Z

130 140 150 160

Temperature (OC)

\

Relative Inlet (ppm)

gas volume SOx NOx

1 I 100 910 230

I

2

I 80 910 170

3 120 910 200

Figure 5 Effects of Temperature

and Gas Flow Rate on

removal Efficiencies

100

il-l!

::: 80 til

:>

o

E

OJ

..: 60

40 200

.-..

150 e

Po

Po

..... 100 M

Z

50 ..:.::

<lI

0 Q(

a l.0 2.0 3.0

Dose (Mrad)

Gas Flow: 3,000 Nm3/hr

Temperature 90°C

Inlet Gas Composition

SOZ ZOO ppm, NOx 200 ppm

~H3 600 ppm

Figure 6 Test Results of Electron

Beam Process

20

IPHAB004248
LITERATOllE CITED

1. The Panel on the EnviroOlental r..pactB of the Conversion to Coal.

Envlroaaent Agenc:y. AD Anal.ysis of the Enviroaaental Impacts of the

Expanded Use of eoal aDd Hit1g8t10n Ke_urea-for the Proper Iaplementation of Enviroomental Impact Assessment (1981) (in Japanese).

2. G. JODes, ll.. Glover. G. Behreos. aDd T. Shirley, Iapact of. HOx

Selective Catalytic Reduction Processes on Flue Gas Cleaning

Systeas. EPA!IEll.L-RTP-1287 (in print) (October 1981).

3. J. Ando. S02 Abatellent for Stationary Sources in Japan. EPA-600/7-

78-210 (NTIS PB 290198) (Hoveaber 1978).

4. J. Ando. HOX Abatellent for Stationary Sources in Japan. EPA-600/7-

79-205 (NTIS PB 80-113673) (August 1979).

5. S. Ta..nuld. H. Kataya... and N. Takaai. 20 ton/h Pilot Plant Test

of Fluid1zed Bed Boiler. In: Proceedings of the Third Coal

Utilization Technology Syaposiua. Coal Mining ll.esearch Center

(Septe~r 1981) (in Japanese).

6. SUII1 tomo Heavy Industries, Total Flue Gas Treatment by the Dry

Desulfurization Process (1981).

7. K. Itaw&Jalra. Pilot Plant Experiment on the !Teatllent of Exhaust Gas

from a Sintering Machine by Electron Beam Irradiation. Environmental

Science aDd Technology, Vol. 14. Ho. 3. 288-293 (March 1980).

8. V. Shui aDd K. KaWlUllUra. Reaoval of SOx and NOx fr01ll Flue Gases by

Electron Radiation. 73rd Annual Meeting of APCA. Montreal (July

1980).

21

IPHAB004249